A multiplicity of hydrocarbons, brines, other liquids and gases and supercritical fluids, slurries, foams and emulsions are produced from, found in, used in the construction of, or injected into subterranean wells. These fluids will be known collectively as downhole fluids. Knowledge of the physical properties of these fluids, such as their density and viscosity, is critical to the drilling, completion, operation, and abandonment of wells. These wells may be used for recovering hydrocarbons from subsurface reservoirs, injecting fluids into subsurface reservoirs, and monitoring the conditions of subsurface reservoirs.
Fluids include matter in its liquid, gaseous, and supercritical states. Downhole fluids include one or more fluids produced from the earth such as hydrocarbons, brines, and other fluids occurring in subsurface reservoirs, as well as fluids such as brines, carbon dioxide, and methane which may be injected into the subsurface to enhance production of hydrocarbons or for disposal purposes. Downhole fluids also include slurries containing liquid and solid components like drilling mud and cement which are used in the construction of wells. One or more downhole fluids may be found simultaneously within a subterranean well, as in a multiphase flow, and they may interact forming emulsions and foams. Downhole fluids will also be understood to include substances which are fluids at reservoir temperature and pressure even if they may be solids at colder temperatures nearer to the surface.
Downhole fluid properties include the viscosity and density of the individual fluid phases as well as the effective viscosity and density of the aggregate fluid consisting of multiple fluid phases. Newtonian fluids are well characterized by a single viscosity. In non-Newtonian fluids, such as slurries, the viscosity may vary with the flow conditions, for example with the stress or shear rate applied to the fluid. Properties of non-Newtonian fluids also include rheological parameters that describe this dependence of viscosity on flow conditions.
Downhole fluid properties are known to vary with temperature and pressure, and the characteristics of this variation is an important property of the downhole fluid. This variation is described, for example, by the PVT (Pressure-Volume-Temperature) characteristics of the fluid which describe how the density varies with pressure and temperature, or by the viscosity variation with pressure and temperature. As pressure and temperature of a fluid changes, the fluid may undergo state changes, for example condensing from a gas to a liquid (e.g., at the dew point), boiling from a liquid to a gas, or transitioning to a supercritical or non-supercritical state. Other types of downhole fluids include structured fluids or dispersions such as emulsions, suspensions and foams, which may undergo structural changes as a function of pressure, temperature, concentration or other chemical or thermodynamic variables. These changes may be detected dynamically as changes in their viscosity and/or density. For instance, one fluid may be dissolved in another and the pressure and temperature conditions under which a fluid becomes dissolved or ceases to be dissolved (e.g., the bubble point) or where solids may precipitate from a fluid is an important property of the fluid. The depth or location in a well where these state changes and this dissolution and precipitation occur is critical information for optimally producing fluids from the well or injecting fluids into the well. Additionally, the density (or API gravity) and viscosity of oil is indicative of its type and value and, as a function of depth, may be used to understand reservoir structure and compartmentalization. Asphaltene content may also be inferred from viscoelastic properties of the produced hydrocarbons. Understanding the PVT characteristics of produced fluids is also important for optimizing surface facilities design, including deciding the optimal pressure for surface separators. State change, dissolution, and precipitation are generally accompanied by a change in viscosity and density of the fluid so that a measurement of viscosity and density as a function of pressure and temperature can identify the temperature and pressure at which these changes occur.
Determining the viscosity and density of fluids in a subsurface reservoir provides important data for optimizing production and reservoir models. Typically, produced fluids are sampled at the surface. Then, in a laboratory, downhole temperature and pressure conditions are applied to the samples and their viscosity, density, and other properties are measured. However, when hydrocarbon liquids from the reservoir are brought to surface temperature and pressure (e.g., as they travel up a well) dissolved gas is released and asphaltenes may precipitate. These changes can be difficult to accurately reverse in the laboratory, so that the viscosity measured in the laboratory may be different from the viscosity that the fluids had in the reservoir, even if the laboratory measurement is made at reservoir temperature and pressure. Furthermore, the process of acquiring samples at a well, transporting them to a laboratory, and making measurements there is costly and time consuming. In addition, the need to transport samples to a lab to acquire fluid properties data prevents these data from being used in real time to respond to changing conditions at the well. Accordingly, there is a need for a sensor that can make an in situ measurement of downhole fluid viscosity and density in downhole or field conditions.
The viscosity and PVT characteristics (or phase diagram) of downhole fluids are typically measured in laboratories and these measurements are used to infer the viscosity and density of the fluid in the reservoir and along the wellbore, and to infer where significant transitions such as state changes, bubble points, and dew points will occur. However, due to the irreversible changes that can occur in fluids as they are brought to the surface as well as uncertainty around exactly where certain conditions of pressure and temperature will be met in the actual well, these inferences may be inaccurate. See Freyss, Henri et al., “PVT Analysis for Oil Reservoirs” RESERVOIR ENGINEERING, The Technical Review, Vol. 37 Number 1, Pages 4-15 Published: Jan. 1, 1989, which is incorporated by reference in its entirety, for a discussion of the viscosity and PVT characteristics of downhole fluids in connection with hydrocarbon recovery. Accordingly, there is a need for a small, fast, and accurate sensor that can measure hydrocarbon viscosity and density along a producing well, as these data combined with temperature, pressure, and depth/location along the well can be used to determine the true locations and conditions where significant transitions occur.
Downhole fluid flows are often two-phase or multi-phase fluid flows, consisting of two or more distinct or immiscible fluids. The flow regime (e.g., slug flow, laminar flow, bubbly flow) depends on the rate of flow of the different phases as well as the viscosity and density of the phases. The flow regime can significantly impact the effectiveness and durability of downhole equipment, such as artificial lift systems. In some flow regimes the flow rates of the different phases may be coupled while in others the flow rates may be uncoupled. Knowing the volume rate of flow of each phase is important for optimizing production and surface facilities, as well as detecting production problems such as water breakthrough. The simplest flow monitoring sensors measure the total flow rate (without distinguishing between the phases) and measure the volume percent of the different phases. The flow rates of the individual phases are determined by multiplying the total flow by the volume percent of each phase. This measurement is only accurate when all phases move at the same velocity. In some flow regimes, the different phases move at different velocities, which can lead to inaccurate measurements. Accordingly there is a need for a small, inexpensive sensor that can measure the instantaneous viscosity and density of the fluid it contacts to aid in the determination of flow regime, the relative abundance of each phase, the shape and size of the flow structures of each phase, and the degree of velocity coupling between fluid phases. Small device size is also necessary due to limited space inside wells particularly in a scenario where permanent or tetherless sensing is desired while not significantly interfering with hydrocarbon production. The invention addresses these and other needs in the art.